Determination method and device for shale gas well discharge and recovery process and storage medium

Abstract

The embodiment of the invention provides a determination method and device for a shale gas well drainage and recovery process and a storage medium, and belongs to the technical field of shale gas well drainage and gas recovery. The determination method of the shale gas well discharge and recovery process comprises the steps that the daily gas production rate and wellhead pressure of a shale gas well are obtained; determining the critical liquid-carrying flow of the shale gas well by using a preset critical liquid-carrying flow model; when the daily gas production rate is smaller than or equal to the critical liquid-carrying flow rate, a first chart is determined in a preset chart library based on the wellhead pressure, and the preset chart library comprises a plurality of drainage and mining process screening charts of the preset wellhead pressure; and based on the first chart, determining the discharge and recovery process of the shale gas well. According to the method, the liquid carrying capacity of the shale gas well and the applicability and economical efficiency of different drainage and mining processes are comprehensively considered, selection of the on-site drainage and mining processes is guided more rapidly and scientifically through the drainage and mining process screening plate, and therefore the problem of well bottom liquid accumulation caused by reduction of the liquid carrying capacity is solved, and the development efficiency and economic benefits of the shale gas well are improved.

Description

Technical Field

[0001] This disclosure relates to the field of shale gas well drainage and gas production technology, specifically to a method, apparatus, and storage medium for determining shale gas well drainage and production processes. Background Technology

[0002] With the development of shale gas fields, the energy of gas wells gradually decreases, gas flow rate continuously declines, and liquid-carrying capacity deteriorates, eventually leading to fluid accumulation at the bottom of the well. The increasing liquid column pressure causes a rise in bottom-hole flowing pressure, reducing the production pressure differential and decreasing production. Therefore, it is urgent to develop appropriate drainage and gas production technologies to improve the recovery rate of shale gas reservoirs.

[0003] Currently, commonly used drainage processes for shale gas wells include: optimized tubing string, bubble drainage, compressor gas lift, plunger gas lift, electric submersible pump, jet pump, etc. When optimizing drainage processes on-site, selection is usually based directly on the technical boundaries of different drainage processes, lacking a comprehensive evaluation of the technology and economic benefits of drainage processes throughout the entire life cycle of shale gas wells. Summary of the Invention

[0004] The purpose of this disclosure is to provide a method, apparatus, and storage medium for determining the drainage process of shale gas wells. This method comprehensively considers factors such as the liquid carrying capacity of shale gas wells, the applicability of drainage process technology at different stages, and the economic benefits of drainage process, thereby comprehensively evaluating the applicability and economy of different drainage processes throughout the entire shale gas cycle, and selecting the optimal drainage process for different periods.

[0005] To achieve the above objectives, in a first aspect, embodiments of this disclosure provide a method for determining the drainage process of a shale gas well. The method includes: obtaining the daily gas production and wellhead pressure of the shale gas well; determining the critical liquid-carrying flow rate of the shale gas well using a preset critical liquid-carrying flow rate model; when the daily gas production is less than or equal to the critical liquid-carrying flow rate, determining a first chart based on the wellhead pressure from a preset chart library, the preset chart library including multiple drainage process screening charts with preset wellhead pressures; and determining the drainage process of the shale gas well based on the first chart.

[0006] In some embodiments, determining a first chart based on wellhead pressure in a preset chart library includes: determining the absolute value of the difference between the wellhead pressure and multiple preset wellhead pressures based on the wellhead pressure; comparing the magnitude of the absolute value of the difference between the wellhead pressure and the multiple preset wellhead pressures, and selecting the drainage process screening chart corresponding to the preset wellhead pressure with the smallest absolute value of the difference with the wellhead pressure as the first chart.

[0007] In some embodiments, the first drawing includes multiple screening areas, each screening area corresponding to at least one drainage process, each drainage process using one drainage technology or a combination of two or more drainage technologies; based on the first drawing, determining the drainage process for a shale gas well includes: obtaining the water-gas ratio of the shale gas well; using the first drawing, based on the daily gas production and the water-gas ratio, determining a preferred area for the shale gas well, the preferred area being one of the multiple screening areas; if the number of drainage processes corresponding to the preferred area is less than 2, then the drainage process corresponding to the preferred area is taken as the determination result; if the number of drainage processes corresponding to the preferred area is ≥ 2, then the drainage processes are ranked according to their economic benefits, and the drainage process with the highest economic benefit is taken as the determination result.

[0008] In some embodiments, the plurality of filtering regions include a first filtering region, a second filtering region, a third filtering region, a fourth filtering region, a fifth filtering region, a sixth filtering region, a seventh filtering region, and / or an eighth filtering region.

[0009] In some embodiments, when the first chart is a screening chart for a drainage process where the preset wellhead pressure is greater than the minimum gas transmission pressure, the multiple screening areas include an eighth screening area; determining the preferred area of ​​a shale gas well based on daily gas production and water-gas ratio includes: when the water-gas ratio is less than or equal to a first threshold and the daily gas production is less than or equal to a first linear function value and greater than a second linear function value, the preferred area is determined as the first screening area; when the water-gas ratio is less than or equal to a second threshold and the daily gas production is less than or equal to a second linear function value and greater than a third linear function value, the preferred area is determined as the second screening area; when the water-gas ratio is greater than a second threshold and less than or equal to a first threshold and the daily gas production is less than or equal to a second linear function value and greater than a third linear function value, the preferred area is determined as the third screening area; when the water-gas ratio is less than or equal to a third threshold and the daily gas production is less than or equal to .... The preferred region is determined as the fourth screening region; when the water-to-gas ratio is greater than the third threshold and less than or equal to the fourth threshold, and the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fifth screening region; when the water-to-gas ratio is greater than the fourth threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the third linear function value, or when the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the fourth linear function value, the preferred region is determined as the sixth screening region; when the water-to-gas ratio is greater than the first threshold, and the daily gas production is less than or equal to the first linear function value and greater than the fourth linear function value, the preferred region is determined as the seventh screening region; when the daily gas production is greater than the first linear function value, the preferred region is determined as the eighth screening region; wherein, the relationship between the first threshold, the second threshold, the third threshold, and the fourth threshold is: third threshold < second threshold < fourth threshold < first threshold.

[0010] In some embodiments, when the first chart is a screening chart for a drainage process where the preset wellhead pressure is less than or equal to the minimum gas transmission pressure, the multiple screening areas do not include the eighth screening area; determining the preferred area for a shale gas well based on daily gas production and water-gas ratio includes: when the water-gas ratio is less than or equal to a first threshold and the daily gas production is greater than a second linear function value, determining the preferred area as the first screening area; when the water-gas ratio is less than or equal to a second threshold and the daily gas production is less than or equal to a second linear function value and greater than a third linear function value, determining the preferred area as the second screening area; when the water-gas ratio is greater than a second threshold and less than or equal to a first threshold, and the daily gas production is less than or equal to a second linear function value and greater than a third linear function value, determining the preferred area as the third screening area; when the water-gas ratio is less than or equal to a third threshold, When the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fourth screening region; when the water-to-gas ratio is greater than the third threshold and less than or equal to the fourth threshold, and the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fifth screening region; when the water-to-gas ratio is greater than the fourth threshold and less than the first threshold, and the daily gas production is less than or equal to the third linear function value, or when the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the fourth linear function value, the preferred region is determined as the sixth screening region; when the water-to-gas ratio is greater than the first threshold and the daily gas production is greater than the fourth linear function value, the preferred region is determined as the seventh screening region; wherein, the relationship between the first threshold, the second threshold, the third threshold, and the fourth threshold is: third threshold < second threshold < fourth threshold < first threshold.

[0011] In some embodiments, before ranking according to the economic benefits of each drainage process, the method further includes: obtaining the cumulative increment of shale gas wells; and using a preset economic benefit model, determining the economic benefit of each drainage process based on the cumulative increment of shale gas wells.

[0012] In some embodiments, the preset economic benefit model is as follows:

[0013] G=PΔN p λ-S f -CΔN p λ-Z f Where G represents the economic benefit of the shale gas well after implementing the drainage process, P represents the selling price per unit of natural gas, and ΔN p The cumulative increase in shale gas well output after the implementation of the drainage process, where λ is the natural gas commercialization rate, and S... f For the equipment / material input required to implement the drainage process, C represents the cost per unit increase in natural gas, and Z represents the cost per unit increase in natural gas. f This refers to equipment depreciation costs.

[0014] In some embodiments, the preset critical liquid carrying flow rate model is determined as follows: under multiple preset liquid volume conditions, experimental data of critical liquid carrying flow rate at different tilt angles are obtained; multiple different critical liquid carrying flow rate models are established, and under multiple preset liquid volume conditions, simulated data of critical liquid carrying flow rate at different tilt angles for each critical liquid carrying flow rate model are obtained; correlation analysis is performed on the experimental data and simulated data, and the critical liquid carrying flow rate model corresponding to the simulated data with the highest correlation to the experimental data is selected as the preset critical liquid carrying flow rate model.

[0015] In some embodiments, the preset critical liquid carrying flow rate is:

[0016] Among them, v cr Let ρ be the critical liquid carrying flow rate, θ be the tilt angle, and ρ be the inclination angle. l For formation water density, ρ g Let σ be the density of natural gas and σ be the interfacial tension between gas and water.

[0017] Secondly, embodiments of this disclosure provide an apparatus for determining the drainage process of a shale gas well. The apparatus includes: an acquisition unit for acquiring the daily gas production and wellhead pressure of the shale gas well; a first determination unit for determining the critical liquid-carrying flow rate of the shale gas well using a preset critical liquid-carrying flow rate model; a second determination unit for determining a first chart based on the wellhead pressure when the daily gas production is less than or equal to the critical liquid-carrying flow rate, the preset chart library including multiple drainage process screening charts with preset wellhead pressures; and a third determination unit for determining the drainage process of the shale gas well based on the first chart.

[0018] Thirdly, embodiments of this disclosure provide a machine-readable storage medium storing instructions that cause a machine to perform the determination method provided in the first aspect or any embodiment of the first aspect.

[0019] By comprehensively considering the liquid-carrying capacity of shale gas wells, the applicability and economy of different drainage processes, and utilizing drainage process screening charts, the selection of drainage processes on-site can be guided more quickly and scientifically. This solves the problem of bottom-hole liquid accumulation caused by decreased liquid-carrying capacity and improves the development efficiency and economic benefits of shale gas wells.

[0020] Other features and advantages of the embodiments disclosed herein will be described in detail in the following detailed description section. Attached Figure Description

[0021] The accompanying drawings are provided to further illustrate the embodiments of this disclosure and form part of the specification. They are used together with the following detailed description to explain the embodiments of this disclosure, but do not constitute a limitation thereof. In the drawings:

[0022] Figure 1 This is a flowchart of a method for determining the drainage process of a shale gas well, provided in an embodiment of this disclosure.

[0023] Figure 2 The liquid volume provided in this embodiment is 1.0m. 3 A schematic diagram showing the critical liquid carrying flow rate at different tilt angles when / d.

[0024] Figure 3 The liquid volume provided in this embodiment is 4.5m. 3 A schematic diagram showing the critical liquid carrying flow rate at different tilt angles when / d.

[0025] Figure 4 The liquid volume provided in this embodiment is 10.0m³. 3 A schematic diagram showing the critical liquid carrying flow rate at different tilt angles when / d.

[0026] Figure 5 This is a schematic diagram of a screening process diagram provided in an embodiment of this disclosure.

[0027] Figure 6 This is a schematic diagram of another screening process provided in this embodiment of the disclosure.

[0028] Figure 7 This is a flowchart illustrating a method for constructing a cumulative increment prediction model for shale gas wells, as provided in an embodiment of this disclosure.

[0029] Figure 8 This is a schematic diagram of a device for determining the drainage process of a shale gas well according to an embodiment of this disclosure. Detailed Implementation

[0030] The specific embodiments of this disclosure will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the scope of this disclosure.

[0031] Figure 1 This is a flowchart of a method for determining the drainage process of a shale gas well, provided in an embodiment of this disclosure.

[0032] like Figure 1 As shown in the embodiments of this disclosure, a method for determining the drainage process of shale gas wells is provided, the method including steps S101 to S104.

[0033] In step S101, the daily gas production and wellhead pressure of the shale gas well are obtained.

[0034] The daily gas production refers to the total amount of natural gas produced by the shale gas well each day, and the wellhead pressure refers to the gas pressure measured at the wellhead of the shale gas well. Obtaining the daily gas production and wellhead pressure can serve as the basis for subsequent determination of whether a drainage process is needed for the shale gas well and, if so, which drainage process to use. In the embodiments of this disclosure, existing technologies such as well logging techniques can be used to obtain the daily gas production and wellhead pressure of the shale gas well, and no specific limitations are imposed on this.

[0035] In step S102, the critical fluid carrying flow rate of the shale gas well is determined using a preset critical fluid carrying flow rate model.

[0036] The critical liquid-carrying flow rate is the minimum flow rate at which gas flow is sufficient to carry liquid to the surface without liquid accumulation. The determined critical liquid-carrying flow rate can serve as the basis for subsequent judgments on whether shale gas wells require drainage processes and, if so, which drainage process to employ.

[0037] In this embodiment of the disclosure, the preset critical liquid carrying flow rate model is established in advance.

[0038] In some embodiments, the preset critical liquid carrying flow rate model can be determined as follows: under multiple preset liquid volume conditions, experimental data of critical liquid carrying flow rate at different tilt angles are obtained; multiple different critical liquid carrying flow rate models are established, and under multiple preset liquid volume conditions, simulated data of critical liquid carrying flow rate at different tilt angles for each critical liquid carrying flow rate model are obtained; correlation analysis is performed on the experimental data and simulated data, and the critical liquid carrying flow rate model corresponding to the simulated data with the highest correlation to the experimental data is selected as the preset critical liquid carrying flow rate model.

[0039] In this embodiment, transient flow experiments of gas-liquid two-phase flow in horizontal, inclined, and vertical pipes can reveal the true flow regime of liquid carrying capacity in shale gas wells. Under different liquid volumes and inclination angles, the critical liquid carrying capacity of the experimental well is analyzed based on the criteria of no reverse flow of the liquid film and no droplet fallback. Furthermore, at least eight classic critical liquid carrying flow rate models can be analyzed. Based on the experimental results, the liquid carrying flow rate model with the closest trend is selected as the preset critical liquid carrying flow rate model for the shale gas well. After establishing the preset critical liquid carrying flow rate model, it is necessary to fit and correct it using actual production data.

[0040] The analysis of at least eight critical fluid-carrying flow rate models aims to comprehensively understand the differences and applicability of different models in predicting the fluid-carrying capacity of shale gas wells, thereby selecting the model most suitable for actual production conditions. These models are typically based on different theoretical assumptions and calculation methods, including but not limited to: the Turner model, the Coleman model, the Li Min model, the Yang Chuandong model, the Wang Yizhong model, the Li Li model, the Belfroid model, and the Yang Wenming model.

[0041] By comparing these models, the critical fluid-carrying flow rate of shale gas wells under different production conditions can be predicted more accurately. Furthermore, actual production data is used for fitting corrections to ensure the accuracy and reliability of the prediction results.

[0042] For example, in this embodiment of the disclosure, indoor experiments were conducted on a target block, and the results were compared with those of various typical critical liquid-carrying flow models (including the Turner model, Coleman model, Li Min model, Yang Chuandong model, Wang Yizhong model, Li Li model, Belfroid model, and Yang Wenming model). The results are as follows: Figure 2 , Figure 3 and Figure 4 As shown, where Figure 2 The liquid volume provided in this embodiment is 1.0m. 3 A schematic diagram showing the critical liquid carrying flow rate at different tilt angles when the flow rate is / d. Figure 3 The liquid volume provided in this embodiment is 4.5m. 3 A schematic diagram showing the critical liquid carrying flow rate at different tilt angles when the flow rate is / d. Figure 4 The liquid volume provided in this embodiment is 10.0m³. 3 A schematic diagram showing the critical liquid carrying flow rate at different tilt angles when / d.

[0043] exist Figure 2 , Figure 3 and Figure 4 In the diagram, the red curve represents the critical liquid carrying capacity curve corresponding to the experimental value, the blue curve represents the critical liquid carrying capacity curve corresponding to the Belfroid model, and the remaining curves represent the critical liquid carrying capacity curves corresponding to other critical liquid carrying capacity models (including the Turner model, Coleman model, Li Min model, Yang Chuandong model, Wang Yizhong model, Li Li model, and Yang Wenming model).

[0044] refer to Figure 2 , Figure 3 and Figure 4 It can be seen that although the error between the predicted and experimental values ​​of the Belfroid model is relatively large, the overall trend of the critical liquid-carrying velocity calculated by the Belfroid model as a function of angle is in good agreement with the experimental test results. Since the trend of the Belfroid model's calculation results as a function of angle is in high agreement with the experimental results of shale gas wells in the target block, it indicates that the angle correction term in the Belfroid model is reasonable and can reflect the variation of the critical liquid-carrying velocity of shale gas wells in this block. Therefore, based on the experimental results, the Belfroid model is selected as the basis for calculating the critical liquid-carrying velocity of shale gas wells in this target block, and an initial preset critical liquid-carrying flow rate model is established, as shown in Formula 1.

[0045] Formula 1: Among them, v cr Critical liquid carrying flow rate, C JY ρ is the correction factor, θ is the tilt angle, and ρ is the tilt angle. l For formation water density, ρ g Let σ be the density of natural gas and σ be the interfacial tension between gas and water.

[0046] Based on the established initial preset critical fluid-carrying flow rate model, and combined with the judgment of whether there is fluid accumulation in the wellbore, the model is further modified to determine its correction coefficient.

[0047] It should be noted that for shale gas wells, the following characteristics will be observed when fluid accumulates in the wellbore:

[0048] (1) An increase in the oil-casing pressure difference (greater than several megapascals) indicates that there is a large flow loss in the oil pipe, insufficient liquid carrying capacity, abnormal lifting, and a large amount of liquid accumulation, meaning that not all the liquid can be carried out.

[0049] (2) The oil pressure and casing pressure drop sharply in a short period of time (significantly greater than the natural decrease).

[0050] (3) Liquid spraying occurs on the ground, and the liquid production or gas-liquid ratio curve fluctuates significantly compared to the previous stable production.

[0051] (4) The gas production in the production curve has decreased significantly compared to the previous stable production.

[0052] (5) The pressure gradient curve obtained from the test shows fluctuations compared to the previous flat curve, and the pressure gradient increases near the bottom of the well.

[0053] Based on the above characteristics, we can analyze and obtain the liquid accumulation data points of 186 wells in 20 wells. Then, we can use the data of these liquid accumulation points to fit a critical liquid carrying capacity model for shale gas wells with high calculation accuracy, such as Formula 2 (the determined correction coefficient is 2.87).

[0054] Formula 2: Among them, v cr Let ρ be the critical liquid carrying flow rate, θ be the tilt angle, and ρ be the inclination angle. l For formation water density, ρ g Let σ be the density of natural gas and σ be the interfacial tension between gas and water.

[0055] In this embodiment of the disclosure, the critical fluid carrying capacity of a shale gas well can be accurately predicted using the aforementioned preset critical fluid carrying capacity model.

[0056] In step S103, when the daily gas production is less than or equal to the critical fluid carrying flow rate, the first chart is determined from the preset chart library based on the wellhead pressure.

[0057] In this embodiment, wellbore fluid accumulation in shale gas wells is predicted by comparing the critical fluid-carrying flow rate and daily gas production. Specifically, when the critical fluid-carrying flow rate is less than the daily gas production, it can be determined that no wellbore fluid accumulation has occurred in the shale gas well, and no drainage process is required; when the critical fluid-carrying flow rate is greater than or equal to the daily gas production, it can be determined that wellbore fluid accumulation has occurred or is about to occur in the shale gas well, and drainage process is required.

[0058] In this embodiment of the disclosure, the preset chart library includes multiple screening charts for drainage and production processes at preset wellhead pressures. For example, the preset chart library may include screening charts for drainage and production processes at preset wellhead pressures P1, P2, and P3.

[0059] In some embodiments, the drainage process screening chart can be drawn based on a preset critical fluid-carrying flow rate model, combined with the technical limits of different drainage processes. For example, based on the critical fluid-carrying flow rate model of shale gas wells, and combined with the technical limits of different drainage processes, drainage process screening charts with wellhead pressures of P1, P2, and P3 can be drawn with the water-gas ratio as the abscissa and the daily gas production as the ordinate.

[0060] It should be noted that different drainage processes have different technical limitations. For example, for jet vortex, its suitable conditions are a discharge rate of <3500m³. 3 / d, water-to-air ratio <5.6m 3 / 10 4 m 3 In this embodiment of the disclosure, the daily gas production is greater than 0.7 times the critical liquid carrying flow rate, etc. When drawing the screening chart of the drainage process, the standard technical limits are adopted. The applicable conditions of daily gas production and water-gas ratio are mainly defined by these limits. The standard technical limits are well known in the industry, and this embodiment of the disclosure will not elaborate on them in detail.

[0061] It should also be noted that for a specific target block, establishing a drainage process screening chart corresponding to the current wellhead pressure in real time requires a significant amount of engineering and time. Therefore, in this embodiment, multiple drainage process screening charts with different preset wellhead pressures are pre-established based on the basic characteristics of the wells in the block. The preset chart library of this embodiment is universal; it can be used interchangeably for wells in blocks with the same basic characteristics. In subsequent use, the drainage process screening chart in the preset chart library can be directly matched as the first chart for the target block to optimize the drainage process, saving time and improving work efficiency. This allows for the selection of the optimal drainage process in a shorter time, timely prevention or improvement of bottomhole fluid accumulation problems in shale gas wells.

[0062] In some embodiments, determining the first chart based on the wellhead pressure in a preset chart library may include: determining the absolute value of the difference between the wellhead pressure and multiple preset wellhead pressures based on the wellhead pressure; comparing the magnitude of the absolute value of the difference between the wellhead pressure and the multiple preset wellhead pressures, and selecting the drainage process screening chart corresponding to the preset wellhead pressure with the smallest absolute value of the difference as the first chart.

[0063] For example, let's take a screening chart for drainage and production processes with three preset wellhead pressures: 6MPa, 4.5MPa, and 2MPa, from the preset chart library. Assuming the current wellhead pressure of the shale gas well is 5.5MPa, the absolute values ​​of the differences between it and these three preset wellhead pressures are 0.5MPa, 1.0MPa, and 3.5MPa, respectively. Since 0.5MPa < 1.0MPa < 3.5MPa, the screening chart for drainage and production processes with a pressure of 6MPa is selected.

[0064] In step S104, the drainage process of the shale gas well is determined based on the first drawing.

[0065] The first panel includes multiple screening areas, each screening area corresponds to at least one sorting process, and each sorting process uses one sorting technology or a combination of two or more sorting technologies.

[0066] It should be noted that the drainage technology used in the drainage process screening diagram of this disclosure includes, but is not limited to: preferred casing, preferred tubing, plunger gas lift, gas lift valve, jet pump, continuous tubing, jet swirl, foam drainage, electric submersible pump, booster, and AIP.

[0067] For example, the first panel may include a first screening area, a second screening area, a third screening area, a fourth screening area, a fifth screening area, a sixth screening area, a seventh screening area, and an eighth screening area. The first screening area may correspond to either a preferred tubing or plunger gas lift drainage process; the second screening area may correspond to either a continuous oil flow or jet swirl drainage process; the third screening area may correspond to either bubble drainage or continuous oil flow; the fourth screening area may correspond to a drainage process using a gas lift valve; the fifth screening area may correspond to a drainage process using a plunger gas lift; the sixth screening area may correspond to a drainage process using an electric submersible pump; the seventh screening area may correspond to either a preferred combination of tubing and gas lift or a jet pump drainage process; and the eighth screening area may correspond to a preferred casing drainage process. It is understood that the preferred combination of tubing and gas lift refers to the combination of these two drainage technologies, and in this embodiment, it is considered as a single drainage process.

[0068] In some embodiments, determining the drainage and production process of a shale gas well based on a first drawing may include: obtaining the water-gas ratio of the shale gas well; using the first drawing, determining a preferred area for the shale gas well based on the daily gas production and the water-gas ratio, wherein the preferred area is one of multiple screening areas; if the number of drainage and production processes corresponding to the preferred area is less than 2, then the drainage and production process corresponding to the preferred area is taken as the determination result; if the number of drainage and production processes corresponding to the preferred area is ≥ 2, then the drainage and production processes are ranked according to their economic benefits, and the drainage and production process with the highest economic benefits is taken as the determination result.

[0069] The water-gas ratio is the ratio of the liquid flow rate to the gas flow rate produced by a shale gas well.

[0070] It should be noted that, since the plotting process is based on a pre-defined critical liquid-carrying flow rate model for shale gas wells, combined with the technical limits of different drainage processes, and plotted with the water-to-gas ratio as the horizontal axis and daily gas production as the vertical axis, a unique screening area can be determined by obtaining the current daily gas production and water-to-gas ratio of the shale gas well. This determined unique screening area is the preferred area.

[0071] It is understood that, since each screening area in this embodiment corresponds to at least one drainage process, when a screening area corresponds to only one drainage process, it means that under the current conditions, only one drainage process is applicable. Therefore, there is no need to consider economic benefits, and this drainage process can be directly used as the drainage process for shale gas wells. However, when a screening area corresponds to two or more drainage processes, it means that under the current conditions, multiple drainage processes are applicable. In this case, it is necessary to add economic benefit considerations to determine the optimal drainage process. The above solution can make the drainage process determined in this embodiment more effective and less costly.

[0072] Specifically, taking the third screening area as an example, which corresponds to either bubble drainage or oil-based drainage, and the fourth screening area as an example, which can use only gas lift valves for drainage. When the determined preferred area is the third screening area, it is necessary to calculate and compare the economic benefits of bubble drainage and oil-based drainage separately. If the economic benefit of bubble drainage is greater than that of oil-based drainage, then bubble drainage will be used as the drainage process for the shale gas well; if the economic benefit of oil-based drainage is greater than that of bubble drainage, then oil-based drainage will be used as the drainage process for the shale gas well. When the determined preferred area is the fourth screening area, then gas lift valves can be directly used as the drainage process for the shale gas well.

[0073] In some embodiments, before ranking according to the economic benefits of each drainage process, the method further includes: obtaining the cumulative increment of shale gas wells; and using a preset economic benefit model, determining the economic benefit of each drainage process based on the cumulative increment of shale gas wells.

[0074] The cumulative increment of shale gas wells can be predicted using a preset cumulative increment prediction model. In this embodiment, the cumulative increment of shale gas wells is mainly used to calculate economic benefits, thereby evaluating the economics of each drainage process and selecting the optimal drainage process.

[0075] In some embodiments, the preset economic benefit model is as shown in Formula 3.

[0076] Formula 3: G = PΔN p λ-S f -CΔN p λ-Z f Where G represents the economic benefit of the shale gas well after implementing the drainage process, P represents the selling price per unit of natural gas, and ΔN p The cumulative increase in shale gas well output after the implementation of the drainage process, where λ is the natural gas commercialization rate, and S... f For the equipment / material input required to implement the drainage process, C represents the cost per unit increase in natural gas, and Z represents the cost per unit increase in natural gas. f This refers to equipment depreciation costs.

[0077] In some embodiments, the plurality of filtering regions include a first filtering region, a second filtering region, a third filtering region, a fourth filtering region, a fifth filtering region, a sixth filtering region, a seventh filtering region, and / or an eighth filtering region.

[0078] Understandably, since wellhead pressure directly affects the gas's liquid-carrying capacity and the gas well's production capacity, it is necessary to establish a screening chart for drainage and production processes under different wellhead pressure conditions to select the optimal process. The minimum gas delivery pressure is a critical value; when the wellhead pressure is greater than the minimum gas delivery pressure, the division of multiple screening zones is basically similar. When the wellhead pressure is less than or equal to the minimum gas delivery pressure, the preferred casing in the aforementioned drainage and production technology will be completely unsuitable, and the drainage and production processes corresponding to different screening zones need to be appropriately adjusted. Therefore, in this embodiment, in addition to dividing the screening zones based on critical liquid-carrying capacity combined with daily gas production and water-gas ratio, it also divides the screening zones based on different wellhead pressure conditions.

[0079] In one specific embodiment, when the first chart is a screening chart for drainage and production processes where the preset wellhead pressure is greater than the minimum gas transmission pressure, multiple screening areas include an eighth screening area, meaning the first chart can be divided into eight screening areas. The correspondence between these eight screening areas and the drainage and production processes is as follows: the first screening area corresponds to preferred tubing or plunger gas lift; the second screening area can correspond to oil connection or jet swirl; the third screening area corresponds to bubble drainage or oil connection; the fourth screening area corresponds to gas lift valve; the fifth screening area corresponds to plunger gas lift; the sixth screening area corresponds to electric submersible pump; the seventh screening area corresponds to a combination of preferred tubing and gas lift or jet pump; and the eighth screening area corresponds to preferred casing.

[0080] Under the given wellhead pressure conditions, the preferred area for shale gas wells, based on daily gas production and water-to-gas ratio, can include:

[0081] When the water-to-gas ratio is less than or equal to the first threshold, and the daily gas production is less than or equal to the first linear function value but greater than the second linear function value, the preferred region is determined as the first screening region.

[0082] When the water-to-gas ratio is less than or equal to the second threshold, and the daily gas production is less than or equal to the second linear function value but greater than the third linear function value, the preferred region is determined as the second screening region.

[0083] When the water-to-gas ratio is greater than the second threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the second linear function value and greater than the third linear function value, the preferred region is determined as the third screening region.

[0084] When the water-to-gas ratio is less than or equal to the third threshold and the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fourth screening region.

[0085] When the water-to-gas ratio is greater than the third threshold and less than or equal to the fourth threshold, and the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fifth screening region.

[0086] When the water-to-gas ratio is greater than the fourth threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the third linear function value, or when the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the fourth linear function value, the preferred region is determined as the sixth screening region.

[0087] When the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the first linear function value but greater than the fourth linear function value, the preferred region is determined as the seventh screening region.

[0088] When the daily gas production exceeds the value of the first linear function, the preferred region is determined as the eighth screening region.

[0089] The order of the first threshold, the second threshold, the third threshold, and the fourth threshold is: third threshold < second threshold < fourth threshold < first threshold.

[0090] In another specific implementation, when the first chart is a screening chart for drainage and production processes where the preset wellhead pressure is less than or equal to the minimum gas delivery pressure, the multiple screening areas do not include the eighth screening area, meaning the first chart can be divided into seven screening areas. The correspondence between these seven screening areas and the drainage and production processes is as follows: the first screening area corresponds to the combination of pressurization and AIP or the combination of pressurization and plunger gas lift; the second screening area corresponds to the combination of pressurization and oil connection or jet swirl; the third screening area corresponds to the combination of pressurization and bubble drainage or oil connection; the fourth screening area corresponds to the gas lift valve; the fifth screening area corresponds to the combination of pressurization and plunger gas lift; the sixth screening area corresponds to the electric submersible pump; and the seventh screening area corresponds to the combination of preferred tubing and gas lift or jet pump.

[0091] Under the given wellhead pressure conditions, the preferred area for shale gas wells, based on daily gas production and water-to-gas ratio, can include:

[0092] When the water-to-gas ratio is less than or equal to the first threshold and the daily gas production is greater than the second linear function value, the preferred region is determined as the first screening region.

[0093] When the water-to-gas ratio is less than or equal to the second threshold, and the daily gas production is less than or equal to the second linear function value but greater than the third linear function value, the preferred region is determined as the second screening region.

[0094] When the water-to-gas ratio is greater than the second threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the second linear function value and greater than the third linear function value, the preferred region is determined as the third screening region.

[0095] When the water-to-gas ratio is less than or equal to the third threshold and the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fourth screening region.

[0096] When the water-to-gas ratio is greater than the third threshold and less than or equal to the fourth threshold, and the daily gas production is less than or equal to the third linear function value, the preferred region is determined as the fifth screening region.

[0097] When the water-to-gas ratio is greater than the fourth threshold and less than the first threshold, and the daily gas production is less than or equal to the third linear function value, or when the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the fourth linear function value, the preferred region is determined as the sixth screening region.

[0098] When the water-to-gas ratio is greater than the first threshold and the daily gas production is greater than the fourth linear function value, the preferred region is determined as the seventh screening region.

[0099] The order of the first threshold, the second threshold, the third threshold, and the fourth threshold is: third threshold < second threshold < fourth threshold < first threshold.

[0100] It should be noted that the values ​​of the first, second, third, and fourth linear functions mentioned above are the limit values ​​for the daily gas production corresponding to the water-gas ratio input to the first, second, third, and fourth linear functions, respectively. Each linear function is determined based on the water-gas ratio and daily gas production applicable to different drainage processes. For example, the first linear function could be y = kx + b, where y is the daily gas production, x is the water-gas ratio, k is the slope coefficient, and b is a constant.

[0101] In this embodiment of the disclosure, the boundary range of each drainage process is determined based on various thresholds of the water-air ratio and various linear functions, thereby realizing the regional division of the first plate.

[0102] In this embodiment of the disclosure, the boundary division of each filtering area can be visualized using a drawing board tool.

[0103] For ease of understanding, the following is combined with Figure 5 and Figure 6 Examples are given to illustrate the division of screening areas for shale gas wells under 6MPa and 2MPa conditions.

[0104] refer to Figure 5 As shown, the first map is divided into 8 regions with the water-to-gas ratio as the horizontal axis and daily gas production as the vertical axis. The first threshold is 10 (unit: m³). 3 / 10 4 m 3 The first threshold corresponds to the red vertical line; the second threshold is 5.5 (unit: m). 3 / 10 4 m 3 ), corresponding to the blue vertical line; the third threshold is 5 (unit: m). 3 / 10 4 m 3 ), corresponding to the green vertical line; the fourth threshold is 8 (unit: m). 3 / 10 4 m 3 The values ​​are represented by purple vertical lines. The first linear function value corresponds to the daily gas production value of the blue diagonal line, the second linear function value corresponds to the daily gas production value of the pink diagonal line, the third linear function value corresponds to the daily gas production value of the red diagonal line, and the fourth linear function value corresponds to the daily gas production value of the black diagonal line. Figures 1-8 correspond to the first to eighth screening areas, respectively, and the corresponding drainage processes are: preferred tubing or plunger gas lift, continuous oil or jet swirl, bubble drainage or continuous oil, gas lift valve, plunger gas lift, electric submersible pump, preferred combination of tubing and gas lift or jet pump, and preferred casing.

[0105] For example, when the water-to-air ratio is 4 (unit: m³) 3 / 10 4 m 3The daily gas production is 10 (unit: 10). 4 m 3 When / d), the preferred region is determined to be region 8.

[0106] refer to Figure 6 As shown, the first chart is divided into 7 regions with the water-to-air ratio as the horizontal axis and daily gas production as the vertical axis. The first threshold is 10, corresponding to the red vertical line; the second threshold is 5.5, corresponding to the blue vertical line; the third threshold is 5, corresponding to the green vertical line; and the fourth threshold is 8, corresponding to the purple vertical line. The second linear function value is the daily gas production value corresponding to the pink diagonal line, the third linear function is the daily gas production value corresponding to the red diagonal line, and the fourth linear function is the daily gas production value corresponding to the black diagonal line. Regions 1-7 in the chart correspond to the first to seventh screening regions, and the corresponding drainage processes are: a combination of pressurization and AIP or a combination of pressurization and plunger gas lift; a combination of pressurization and oil extraction or jet swirl; a combination of pressurization and bubble drainage or oil extraction; a gas lift valve; a combination of pressurization and plunger gas lift; an electric submersible pump; a combination of optimized tubing and gas lift or a jet pump.

[0107] For example, when the water-to-air ratio is 4 (unit: m³) 3 / 10 4 m 3 The daily gas production is 1 (unit: 10). 4 m 3 When / d), the preferred region is determined to be region 2.

[0108] The above technical solution mainly utilizes drainage process screening charts to determine the preferred areas, thereby selecting suitable drainage processes. When only one suitable drainage process is selected from the drainage process chart, this process is the optimal drainage process for the shale gas well. When multiple drainage processes are selected, the economic benefits of the selected drainage processes are evaluated by combining the cumulative increase prediction results of the shale gas well with the economic evaluation model, and the drainage process with the highest economic benefit is selected as the optimal result.

[0109] For example, in this embodiment of the disclosure, the drainage process of 10 shale gas wells in the target block was optimized, and the results are shown in Table 1.

[0110] Table 1 Optimal Drainage Process

[0111]

[0112] Taking Well-1 as an example, as shown in Table 1, the drainage processes selected through technical screening (i.e., drawing screening) for Well-1 include bubble drainage, pressurization, and oil-connected drainage. Since multiple drainage processes exist, an economic evaluation of each process was conducted, yielding the result: bubble drainage > pressurization > oil-connected drainage, meaning bubble drainage has the highest economic benefit. Since all three drainage processes are applicable, to save costs, the drainage process with the highest economic benefit is selected, i.e., bubble drainage is preferred.

[0113] This disclosure comprehensively evaluates the liquid-carrying capacity of shale gas wells, performs technology screening, and conducts economic evaluation to achieve optimal shale gas well drainage and production processes throughout their entire lifecycle. The liquid-carrying capacity evaluation provides the foundation for subsequent technology screening. The technology screening section, based on a critical liquid-carrying flow rate calculation model and the technological limits of different drainage and production processes at different stages, pre-establishes a preset chart library containing multiple drainage and production process screening charts. The economic evaluation section ranks processes based on their economic benefits, using investment returns as the standard. This disclosure can comprehensively evaluate the applicability and economics of different drainage and production processes throughout the entire shale gas lifecycle and select the optimal drainage and production process for different periods.

[0114] Figure 7 This is a flowchart illustrating a method for constructing a cumulative increment prediction model for shale gas wells, as provided in an embodiment of this disclosure.

[0115] like Figure 7 As shown in the embodiments of this disclosure, a method for constructing a cumulative increment prediction model for shale gas wells is provided, the method including steps S201 to S204.

[0116] In step S201, the reference sequence and the comparison sequence are determined.

[0117] Specifically, the grey relational analysis (GRA) method was used to analyze the impact of different drainage process factors on the cumulative increment of the process, and the main indicators affecting the cumulative increment were identified, as shown in Table 2.

[0118] Table 2. Main indicators confirmed by grey relational analysis.

[0119] Key Indicators Lithology Key Indicators pressure coefficient Key Indicators TOC Key Indicators Brittleness Index Key Indicators Ro Key Indicators Burial depth Key Indicators Porosity Key Indicators Horizontal stress difference coefficient Key Indicators gas content Key Indicators Degree of development of natural cracks

[0120] In this embodiment of the disclosure, the cumulative increment of shale gas wells is used as the comparison sequence X0, and the parameters affecting the cumulative increment are used as the reference sequence X1, X2, ..., X... n .

[0121] get

[0122] In some embodiments, after determining the reference sequence and the comparison sequence, it is also necessary to make the reference sequence and the comparison sequence dimensionless.

[0123] Specifically, common methods for dimensionless transformation include averaging (e.g., Formula 4) or dividing by the data in the first column (e.g., Formula 5).

[0124] Formula 4:

[0125] Formula 5:

[0126] After dimensionless transformation, we obtain

[0127] In step S202, the maximum difference and minimum difference between the reference sequence and the comparison sequence are determined based on the reference sequence and the comparison sequence.

[0128] Specifically, the absolute differences between the reference sequence and the comparison sequence are calculated to form an absolute difference matrix:

[0129]

[0130] The maximum and minimum numbers in the absolute difference matrix are the maximum and minimum differences, respectively.

[0131]

[0132] In step S203, the correlation between the reference sequence and the comparison sequence is determined based on the maximum difference and the minimum difference, and the reference sequence with a correlation greater than a preset threshold is selected as the key factor.

[0133] Specifically, based on the maximum difference and the minimum difference, the correlation coefficient between the reference sequence and the comparison sequence is calculated using the correlation coefficient calculation formula, where the correlation coefficient calculation formula is shown in Formula 6.

[0134] Formula 6: In the formula: ρ∈(0,1), take values ​​from 0.1 to 0.5, usually take 0.5, the smaller the value, the more it can improve the difference between correlation coefficients.

[0135] The correlation coefficient matrix can be obtained as follows:

[0136] The correlation degree is the average of the correlation coefficients of the corresponding indicators, that is...

[0137] In step S204, the key factors obtained from grey relational analysis are used as input, and the cumulative increment of shale gas wells is used as output. Through the determined neural network function and neural network training method, a prediction model for the cumulative increment of shale gas wells is trained.

[0138] In some embodiments, the Sigmoid function can be selected as the transfer function, the Purelin function can be selected as the output layer transfer function, and the LM (Levenberg Marquardt) method can be used as the training method.

[0139] Specifically, the key factors obtained from grey relational analysis serve as input nodes for the BP artificial neural network, while the output node represents the cumulative increment of shale gas wells. The sample wells are divided into n parts, with one part serving as the test sample and the remaining n-1 parts as the training sample. During training, the input and output data are normalized, and weights and thresholds are assigned to each layer for training. During training, the relevant parameters are adjusted according to requirements until the model meets the error requirements, thereby enabling the prediction of the cumulative increment of shale gas wells.

[0140] The cumulative increment prediction model constructed above can accurately predict the cumulative increment of shale gas wells.

[0141] Figure 8 This is a schematic diagram of a device for determining the drainage process of a shale gas well according to an embodiment of this disclosure, as shown below. Figure 8 As shown, the determining device 100 includes: an acquisition unit 110, a first determining unit 120, a second determining unit 130, and a third determining unit 140.

[0142] The system includes three main components: Acquisition unit 110, which acquires the daily gas production and wellhead pressure of the shale gas well; First determination unit 120, which determines the critical liquid-carrying flow rate of the shale gas well using a preset critical liquid-carrying flow rate model; Second determination unit 130, which determines a first chart based on the wellhead pressure from a preset chart library when the daily gas production is less than or equal to the critical liquid-carrying flow rate, wherein the preset chart library includes multiple drainage and production process screening charts for preset wellhead pressures; and Third determination unit 140, which determines the drainage and production process of the shale gas well based on the first chart.

[0143] For specific details and benefits of the apparatus for determining the shale gas well drainage process provided in the embodiments of this disclosure, please refer to the above description of the method for determining the shale gas well drainage process, which will not be repeated here.

[0144] In this embodiment of the disclosure, a machine-readable storage medium is also provided, on which instructions are stored, which are used to cause a machine to execute a method for determining the shale gas well drainage process provided in the above embodiments of the disclosure.

[0145] It should be noted that although the terms "first," "second," etc., are used herein to describe different modules, steps, and data in the embodiments of this disclosure, these terms are only for distinguishing between different modules, steps, and data, and do not indicate a specific order or degree of importance. In fact, the terms "first," "second," etc., can be used interchangeably.

[0146] Although the operations are described in a specific order in the accompanying drawings, this should not be construed as requiring these operations to be performed in the specific order or serial order shown, or requiring all of the operations shown to obtain the desired result. In certain environments, multitasking and parallel processing may be advantageous.

[0147] The acquisition, transmission, storage, use, and processing of data in this embodiment comply with the relevant provisions of national laws and regulations.

[0148] It should be noted that in the embodiments disclosed herein, certain software, components, models, and other existing solutions in the industry may be mentioned. These should be considered as exemplary and are intended only to illustrate the feasibility of implementing the technical solutions disclosed herein. However, they do not mean that the applicant has used or necessarily used such solutions.

[0149] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0150] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for determining the drainage process of a shale gas well, characterized in that, The method includes: Obtain the daily gas production and wellhead pressure of the shale gas well; The critical fluid carrying capacity of the shale gas well is determined using a pre-defined critical fluid carrying capacity model. When the daily gas production is less than or equal to the critical liquid carrying flow rate, a first chart is determined in the preset chart library based on the wellhead pressure. The preset chart library includes multiple drainage process screening charts with preset wellhead pressures. Based on the first drawing, the drainage process of the shale gas well is determined.

2. The determination method according to claim 1, characterized in that, The step of determining the first chart from the preset chart library based on the wellhead pressure includes: Based on the wellhead pressure, determine the absolute value of the difference between the wellhead pressure and multiple preset wellhead pressures; Compare the absolute values ​​of the differences between the wellhead pressure and multiple preset wellhead pressures, and select the drainage process screening chart corresponding to the preset wellhead pressure with the smallest absolute value of the difference with the wellhead pressure as the first chart.

3. The determination method according to claim 1, characterized in that, The first chart includes multiple screening areas, each screening area corresponding to at least one drainage process, and each drainage process uses one drainage technology or a combination of two or more drainage technologies; determining the drainage process of the shale gas well based on the first chart includes: Obtain the water-gas ratio of the shale gas well; Using the first chart, based on the daily gas production and the water-gas ratio, a preferred area for the shale gas well is determined, where the preferred area is one of the plurality of screening areas; If the number of drainage processes corresponding to the preferred region is less than 2, then the drainage process corresponding to the preferred region will be the determination result. If there are ≥2 types of drainage processes corresponding to the preferred area, then the drainage processes are ranked according to their economic benefits, and the drainage process with the highest economic benefits is determined.

4. The determination method according to claim 3, characterized in that, The plurality of filtering regions include a first filtering region, a second filtering region, a third filtering region, a fourth filtering region, a fifth filtering region, a sixth filtering region, a seventh filtering region, and / or an eighth filtering region.

5. The determination method according to claim 4, characterized in that, When the first chart is a screening chart for a drainage process where the preset wellhead pressure is greater than the minimum gas transmission pressure, the multiple screening areas include an eighth screening area; determining the preferred area of ​​the shale gas well based on the daily gas production and the water-gas ratio includes: When the water-to-gas ratio is less than or equal to the first threshold, and the daily gas production is less than or equal to the first linear function value and greater than the second linear function value, the preferred region is determined as the first screening region. When the water-to-gas ratio is less than or equal to the second threshold, and the daily gas production is less than or equal to the second linear function value but greater than the third linear function value, the preferred region is determined as the second screening region. When the water-to-gas ratio is greater than the second threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the second linear function value and greater than the third linear function value, the preferred region is determined to be the third screening region. When the water-to-gas ratio is less than or equal to the third threshold and the daily gas production is less than or equal to the third linear function value, the preferred region is determined to be the fourth screening region. When the water-to-gas ratio is greater than the third threshold and less than or equal to the fourth threshold, and the daily gas production is less than or equal to the third linear function value, the preferred region is determined to be the fifth screening region. When the water-to-gas ratio is greater than the fourth threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the third linear function value, or when the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the fourth linear function value, the preferred region is determined to be the sixth screening region; When the water-to-gas ratio is greater than the first threshold, and the daily gas production is less than or equal to the first linear function value and greater than the fourth linear function value, the preferred region is determined to be the seventh screening region. When the daily gas production is greater than the value of the first linear function, the preferred region is determined to be the eighth screening region; The relationship between the first threshold, the second threshold, the third threshold, and the fourth threshold is: third threshold < second threshold < fourth threshold < first threshold.

6. The determination method according to claim 4, characterized in that, When the first chart is a screening chart for a drainage process where the preset wellhead pressure is less than or equal to the minimum gas transmission pressure, the plurality of screening areas does not include the eighth screening area; the determination of the preferred area for the shale gas well based on the daily gas production and the water-gas ratio includes: When the water-to-gas ratio is less than or equal to the first threshold and the daily gas production is greater than the second linear function value, the preferred region is determined as the first screening region. When the water-to-gas ratio is less than or equal to the second threshold, and the daily gas production is less than or equal to the second linear function value but greater than the third linear function value, the preferred region is determined as the second screening region. When the water-to-gas ratio is greater than the second threshold and less than or equal to the first threshold, and the daily gas production is less than or equal to the second linear function value and greater than the third linear function value, the preferred region is determined to be the third screening region; When the water-to-gas ratio is less than or equal to the third threshold and the daily gas production is less than or equal to the third linear function value, the preferred region is determined to be the fourth screening region. When the water-to-gas ratio is greater than the third threshold and less than or equal to the fourth threshold, and the daily gas production is less than or equal to the third linear function value, the preferred region is determined to be the fifth screening region. When the water-to-gas ratio is greater than the fourth threshold and less than the first threshold, and the daily gas production is less than or equal to the third linear function value, or when the water-to-gas ratio is greater than the first threshold and the daily gas production is less than or equal to the fourth linear function value, the preferred region is determined to be the sixth screening region. When the water-to-gas ratio is greater than the first threshold and the daily gas production is greater than the fourth linear function value, the preferred region is determined to be the seventh screening region. The relationship between the first threshold, the second threshold, the third threshold, and the fourth threshold is: third threshold < second threshold < fourth threshold < first threshold.

7. The determination method according to claim 3, characterized in that, Before ranking based on the economic benefits of each drainage process, the method further includes: Obtain the cumulative increment of the shale gas well; Using a pre-defined economic benefit model, the economic benefits of each drainage process are determined based on the cumulative increment of the shale gas wells.

8. The determination method according to claim 7, characterized in that, The preset economic benefit model is as follows: G=PΔN p λ-S f -CΔN p λ-Z f , Where G represents the economic benefit of the shale gas well after implementing the drainage process, P represents the selling price per unit of natural gas, and ΔN p The cumulative increase in shale gas well output after the implementation of the drainage process, where λ is the natural gas commercialization rate, and S... f For the equipment / material input required to implement the drainage process, C represents the cost per unit increase in natural gas, and Z represents the cost per unit increase in natural gas. f This refers to equipment depreciation costs.

9. The determination method according to claim 1, characterized in that, The preset critical liquid-carrying flow rate model is determined in the following way: Experimental data on critical liquid carrying flow rate at different tilt angles were obtained under multiple preset liquid volume conditions. Establish multiple critical liquid carrying flow rate models, and under the multiple preset liquid volume conditions, obtain simulation data of critical liquid carrying flow rate at different tilt angles for each critical liquid carrying flow rate model; A correlation analysis is performed on the experimental data and the simulated data, and the critical liquid-carrying flow rate model corresponding to the simulated data with the highest correlation with the experimental data is selected as the preset critical liquid-carrying flow rate model.

10. The determining method according to any one of claims 1-9, characterized in that, The preset critical liquid carrying flow rate model is as follows: Among them, v cr Let ρ be the critical liquid carrying flow rate, θ be the tilt angle, and ρ be the inclination angle. l For formation water density, ρ g Let σ be the density of natural gas and σ be the interfacial tension between gas and water.

11. A device for determining the drainage process of a shale gas well, characterized in that, The device includes: The acquisition unit is used to acquire the daily gas production and wellhead pressure of the shale gas well; The first determining unit is used to determine the critical fluid carrying flow rate of the shale gas well using a preset critical fluid carrying flow rate model. The second determining unit is used to determine a first chart in a preset chart library based on the wellhead pressure when the daily gas production is less than or equal to the critical liquid carrying flow rate. The preset chart library includes multiple drainage and production process screening charts with preset wellhead pressures. The third determining unit is used to determine the drainage process of the shale gas well based on the first drawing.

12. A machine-readable storage medium, characterized in that, The machine-readable storage medium stores instructions for causing the machine to perform the determination method as described in any one of claims 1-10.

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